The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
This invention relates to treating subterranean formations penetrated by a wellbore and in particular to the inhibition of fines migration in the completion, stimulation and other treatment operations involving subterranean formations.
Viscous fluids play many important roles in oilfield service applications, for instance in gravel packing placement. Gravel packing essentially consists of placing a gravel pack around the perimeter of a wellbore across the production zone to minimize sand production from highly permeable formations.
Solid suspension properties are also an important requirement for fracturing fluids. For a well to produce hydrocarbons from a subterranean geologic formation, the hydrocarbons have to follow a sufficiently unimpeded flow path from the reservoir to the wellbore. If the formation has relatively low permeability, either naturally or through formation damages resulting for example from addition of treatment fluids or the formation of scales, it can be fractured to increase the permeability. Fracturing involves literally breaking a portion of the surrounding strata, by injecting a fluid directed at the face of the geologic formation, at pressures sufficient to initiate and/or extend a fracture in the formation. A fracturing fluid typically comprises a proppant, such as ceramic beads or sand to hold the fracture open after release of hydraulic pressure. It is therefore important for the fluid to be viscous enough to carry the proppant into the fracture.
Water-soluble polymers, such as polysaccharide derivatives, are the most commonly used additives to obtain fluid viscosity. Viscosity may also be obtained using viscoelastic surfactants. Unlike the polymers, viscoelastic surfactant based fluids do not lead to reduction of permeability due to solid deposits, and exhibit lower friction pressure. In addition, the viscosity of the fluid is reduced or lost upon exposure to formation fluids such as for instance crude oil thereby ensuring better fracture clean-up.
The normal preparation of viscoelastic surfactant fluids includes mixing in appropriate amounts suitable surfactants such as anionic, cationic, nonionic and zwitterionic surfactants. The viscosity of viscoelastic surfactant fluids is attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting elastic behavior. In this specification and claims, “micelle” is a generic term for the organized interacting species.
Cationic viscoelastic surfactants—typically consisting of long-chain quaternary ammonium salts such as cetyltrimethylammonium bromide (CTAB)—have been of interest in wellbore fluids. Common reagents that generate viscoelasticity in the surfactant solutions are salts such as ammonium chloride, potassium chloride, sodium salicylate and sodium isocyanate and non-ionic organic molecules such as chloroform. The electrolyte content of surfactant solutions is also an important control on their viscoelastic behavior. However, fluids comprising this type of cationic viscoelastic surfactants usually tend to lose viscosity at high brine concentration (10 pounds per gallon or more). Therefore, these fluids have seen limited use as gravel-packing fluids or drilling fluids, or in other applications requiring heavy fluids to balance well pressure.
Amphoteric or zwitterionic surfactants and an optional organic acid, salt and/or inorganic salt may be used impart viscoelastic properties. The surfactants are for instance dihydroxyl alkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkyl amidopropyl betaine and alkylamino mono- or di-propionates derived from certain waxes, fats and oils. The surfactants work in conjunction with an inorganic water-soluble salt or organic additive such as phthalic acid, salicylic acid or their salts. Amphoteric/zwitterionic surfactants, in particular those comprising a betaine moiety are useful at temperature up to about 150° C. and are therefore of particular interest for medium to high temperature wells. However, like the cationic viscoelastic surfactants mentioned above, they are not generally compatible with high brines, i.e. brine with a saline content such that the density is 1.2 g/mL (10 lb/gal) or more.
Sodium dodecylbenzenesulfonate (SDBS) may be used with amphoteric or zwitterionic surfactants to viscosify high brines. One embodiment of a zwitterionic surfactant comprises a betaine moiety and an oleic acid moiety, such as the surfactant in BET-O-30 (Rhodia). The oleic acid stock from which the oleic acid moiety is derived is generally about 75% pure to about 85% pure, and the balance of the stock comprises other fatty acids, such as linolic acid, linoleic acid, etc. Some of these other fatty acids may be present in about 15% to about 25% of the molecules of the surfactant in place of the oleic acid.
In various oilfield stimulation applications, fines migration can cause formation damage leading to a loss of productivity of a well. Fines migration can affect fracturing, matrix acidizing and sand control operations in well services, and thus the art has attempted to prevent potential formation damage. A common approach for fines stabilization is to use potassium chloride, ammonium chloride, tetramethyl ammonium chloride, and the like; however, these additives only provide temporary protection from fines migration. After the treatment is completed, the well placed into production and the original treatment fluid is displaced and the temporary stabilizer removed, the fines can resume migration and eventually damage the formation and reduce the production rates.
Permanent fines inhibitors may require multiple treatment steps and/or rigorously controlled treatment conditions and protocols, are can be time consuming, complicated and expensive. There is a need in the art for a simple and cost-effective treatment method to more permanently inhibit and control fines migration.
Drilling fluids used to form boreholes in shale or clay deposits have been stabilized using various shale stabilizers. In some cases, polyamines and polyol compounds are used to stabilize water-sensitive solids during drilling operations. On the other hand, especially where the wellbores are cased, there is no need for permanent stabilization or the inhibition of fines migration by a drilling fluid. Moreover, it is known that the use of amine compounds can have a deleterious effect on the rheology of viscoelastic surfactant systems.